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HIGHLIGHTS

	Three Months Ended September 30					Nine Months Ended September 30
(unaudited)	2002	2001		% Change		2002		2001	% Change
FINANCIAL
($ thousands, except per share amounts)
Petroleum and natural gas sales	94,633	101,689		(7	)	265,270		265,373	—
Cash flow from operations	48,637	46,330		5		137,970		119,717	15
Per share — basic	0.93	0.89		5		2.65		2.45	8
— diluted	0.91	0.87		5		2.60		2.40	8

Net income (loss)	3,687	(4,626	)	n/a		32,345		4,264	659
Per share — basic	0.07	(0.09	)	n/a		0.62		0.09	589
— diluted	0.07	(0.09	)	n/a		0.61		0.09	578

Exploration and development	30,390	33,208		(8	)	103,572		116,413	(11	)
Acquisitions — net	471	705		(33	)	(42,615	)	291,680	n/a
Total capital expenditures	30,861	33,913		(9	)	60,957		408,093	(85	)

Long-term notes						328,261		326,853	—
Bank loans						—		129,610	(100	)
Other working capital deficiency						15,697		40,702	(61	)
Total net debt						343,958		497,165	(31	)

OPERATING
Daily production
Light oil (bbls/d)	2,999	6,077		(51	)	3,237		4,931	(34	)
Heavy oil (bbls/d)	23,504	29,078		(19	)	23,616		27,209	(13	)
Total oil (bbls/d)	26,503	35,155		(25	)	26,853		32,140	(16	)
Natural gas (mmcf/d)	71.3	78.2		(9	)	72.8		69.1	5
Oil equivalent (boe/d @ 6:1)	38,391	48,187		(20	)	38,986		43,656	(11	)
Average prices (before hedging)
WTI oil (US$/bbl)	28.27	26.49		7		25.39		27.73	(8	)
Edmonton par oil ($/bbl)	44.02	40.37		9		39.31		41.85	(6	)
BTE light oil ($/bbl)	37.36	35.37		6		32.71		36.92	(11	)
BTE heavy oil ($/bbl)	31.03	23.75		31		26.50		18.61	42
BTE total oil ($/bbl)	31.75	25.76		23		27.25		21.42	27
BTE natural gas ($/mcf)	3.33	3.35		(1	)	3.49		4.91	(29	)
BTE oil equivalent ($/boe)	28.10	24.23		16		25.28		23.54	7
Weighted average shares (thousands)
Basic	52,315	52,226		—		52,151		48,884	7
Diluted	53,278	53,154		—		53,043		49,812	6

MESSAGE TO SHAREHOLDERS

Baytex Energy Ltd. is pleased to announce its operating and financial results for the third quarter ended September 30, 2002. Highlights of the quarter include:

• cash flow increased by 5% over Q3/01;

• net debt decreased by $153 million or 31% compared to twelve months ago;

• achieving 10% growth in year-end exit production; and

• signed five-year heavy oil supply agreement at long-term average differential.

Oil price continued to be buoyed by political reasons during the third quarter, with WTI averaging US$28.27 or 8% higher than the second quarter average of this year. Higher seasonal demand for heavy oil also caused the LLK differential to further narrow in the third quarter to US$6.00 per barrel or 21% of WTI. Consequently, Baytex’s average heavy oil wellhead price increased to $31.03 per barrel in the current quarter, the highest it has been since the third quarter of 2000. World oil prices have retreated modestly so far in the fourth quarter as the “war premium” is reduced by the ease in political tension. Heavy oil differentials, as expected, have increased to the 30% of WTI range as product demand decreases heading into the winter season.

Gas price took an opposite path when compared to heavy oil price. Transportation issues during the third quarter caused prices at AECO to temporarily diverge from NYMEX prices, resulting in Baytex average wellhead price dropping to $3.33 per mcf, or 15% lower than that for the second quarter this year. Prices for the fourth quarter, however, will be substantially stronger with higher NYMEX prices and a normalized basis differential to AECO.

Cash flow for the third quarter of 2002 was $0.93 per share, an increase of 5% over the same quarter one year ago. This increase is especially gratifying as Baytex’s total net debt as at September 30, 2002 was $153 million or 31% lower than that of twelve months ago, indicating that the dramatic improvement in financial strength was achieved without profit potential being impaired. In addition, the profile of the Company’s cash flow in 2002 demonstrates the benefits of its production mix. Notwithstanding the significant volatilities in oil and gas prices, cash flow for the third quarter of $0.93 per share is comparable to the $0.95 per share reported in the second quarter and cash flow for the fourth quarter is also expected to be in this similar range. Net income for the third quarter was reduced by an unrealized foreign exchange loss of $7.8 million upon the conversion of the Company’s US$ denominated debt. Excluding this loss, net income for the quarter would have been $11.5 million ($0.22 per share) compared to $2.4 million ($0.04 per share) for the same period last year.

The stability of Baytex’s future cash flow will be further enhanced by the recent signing of a long-term supply agreement. On October 16, 2002, Baytex announced the signing of a long-term crude oil supply agreement with Frontier Oil and Refining Company of Denver, Colorado. The agreement calls for the delivery by Baytex of 20,000 barrels per day of Lloydminster Blend (LLB) crude oil at a price fixed at 71% of NYMEX WTI oil price (i.e. LLB differential fixed at 29% of WTI) for an initial term of five years commencing January 1, 2003. During the first year of this term, the contracted volume will increase gradually from 9,000 barrels per day in January reaching the full 20,000 barrels per day in October 2003 and thereafter. Each barrel of LLB crude constitutes approximately 80% of heavy oil produced by Baytex and 20% of diluent.

Lloydminster Blend oil differentials have averaged 29% of WTI price for the last 17 years since price deregulation in 1985. By signing this agreement at the long-term average differential, Baytex has greatly reduced its corporate exposure to heavy oil pricing volatilities. The improved stability in cash flow will better position the Company to manage its capital programs and production growth plans. The superior re-investment efficiency of Baytex’s heavy oil assets, due to their low royalties and low operating and finding and development costs, will be further enhanced by this reduced pricing exposure.

Capital expenditures for the third quarter totaled $30.9 million, representing 63% of cash flow from operations. During the quarter, the Company drilled 38 (33.9 net) wells, resulting in 24 (23.2 net) oil wells; nine (5.7 net) gas wells, two (2.0 net) service wells and three (3.0 net) dry holes. This capital program was carefully controlled in order to allow Baytex to eliminate its bank borrowings entirely during the third quarter. This objective was achieved and exceeded with the Company having $11.4 million in cash investments at September 30, 2002.

In early October, Baytex bolstered its operating position in the Cold Lake area through the purchase of approximately 2,500 barrels per day of primary heavy oil production and 44,000 net acres of undeveloped land adjacent to its existing properties in this area. The Company has identified approximately 200 development drilling locations on the new lands acquired. Together with its existing development potential acquired in 2001, Cold Lake will provide Baytex with an expanded drilling inventory for heavy oil production growth over the next few years. The purchase price of $32.9 million was funded by cash and bank borrowings. The Company targets to have the bank loans incurred for this purchase completely repaid by the end of this year.

The remainder of the fourth quarter capital program is approximately $30 million and will include delineation drilling in the Cold Lake area, selective development drilling in the Ferrier and Leahurst areas, as well as preparation for the upcoming winter drilling program. At the Company’s VAPEX pilot project at Carruthers North, oil production from the test wells has increased from the pre-injection three bbl/d to 25 bbl/d. Baytex is encouraged by this initial response and will continue with the pilot program through the fourth quarter.

Baytex is excited about its prospects entering 2003. The Company is well positioned to deliver a minimum 10% in production growth next year. It is committed to further increase its financial strength from the solid foundation achieved in 2002. The long-term supply agreement effectively eliminates the additional price risk of a majority of the Company’s heavy oil production as uncontracted heavy oil will account for less than 25% of Baytex’s overall production when the supply agreement is fully implemented. Baytex is hopeful that the excellent fundamentals underlying its operations will translate into superior returns for its stakeholders.

On behalf of the Board of Directors

Dale O. Shwed

President and Chief Executive Officer

November 11, 2002

MANAGEMENT’S DISCUSSION AND ANALYSIS

Management’s discussion and analysis (“MD&A”) should be read in conjunction with the unaudited interim consolidated financial statements for the three months and the nine months ended September 30, 2002 and the audited consolidated financial statements and MD&A for the year ended December 31, 2001. Per barrel of oil equivalent (“boe”) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.

PRODUCTION

Light oil production for the third quarter of 2002 decreased by 51% to 2,999 bbl/d from 6,077 bbl/d a year earlier due to the sale of properties in December 2001 and January 2002. Heavy oil production for the quarter decreased by 19% to 23,504 bbl/d from 29,078 bbl/d as a result of property sales and decreased capital spending. Natural gas production decreased by 9% to 71.3 mmcf/d for the third quarter of 2002 compared to 78.2 mmcf/d for the same period last year due to dispositions and the debt reduction program.

For the first nine months of 2002, light oil production decreased by 34% to 3,237 bbl/d from 4,931 bbl/d for the same period of 2001 and heavy oil production decreased 13% to 23,616 bbl/d for the first nine months of 2002 from 27,209 bbl/d a year ago, both due to the factors noted for the third quarter comparison. Natural gas production increased by 5% to 72.8 mmcf/d for the first nine months of 2002 compared to 69.1 mmcf/d for 2001 due to the acquisitions completed in the second quarter of 2001.

REVENUE

Petroleum and natural gas sales decreased by 7% to $94.6 million for the third quarter of 2002 from $101.7 million for the third quarter of 2001. For the first nine months of 2002, petroleum and natural gas sales were $265.3 million, consistent with sales of $265.4 million a year earlier.

Three Months ended September 30	2002				2001
	$000s		$/Unit		$000s		$/Unit
Oil revenue (barrels)
Light oil	10,307		37.36		19,772		35.37
Heavy oil	67,105		31.03		63,538		23.75
Derivative contracts gain (loss)	(6,704	)	(2.75	)	(5,747	)	(1.78	)
Total oil revenue	70,708		29.00		77,563		23.98
Natural gas revenue (mcf)	21,850		3.33		24,126		3.35
Derivative contracts gain (loss)	2,075		0.32		—		—
Total natural gas revenue	23,925		3.65		24,126		3.35
Total revenue (boe @ 6:1)	94,633		26.79		101,689		22.94

Revenue from light oil for the third quarter of 2002 decreased 48% from the same period a year ago due to a 51% decrease in production and a 6% increase in wellhead price. Revenue from heavy oil increased 6% as a 31% increase in wellhead price offset a 19% decline in production. Revenue from natural gas decreased 9% due to a 1% decrease in wellhead price and a 9% decrease in production.

Nine Months ended September 30	2002				2001
	$000s		$/Unit		$000s		$/Unit
Oil revenue (barrels)
Light oil	28,907		32.71		49,708		36.92
Heavy oil	170,844		26.50		138,225		18.61
Derivative contracts gain (loss)	(6,576	)	(0.90	)	(15,210	)	(1.73	)
Total oil revenue	193,175		26.35		172,723		19.68
Natural gas revenue (mcf)	69,300		3.49		92,650		4.91
Derivative contracts gain (loss)	2,795		0.14		—		—
Total natural gas revenue	72,095		3.63		92,650		4.91
Total revenue (boe @ 6:1)	265,270		24.92		265,373		22.27

For the first nine months of 2002, light oil revenue decreased 42% from the same period of 2001 due to a 34% decrease in production and an 11% decline in wellhead price. Revenue from heavy oil increased 24% as a result of a 42% increase in wellhead price, which offset a 13% decrease in production. Revenue from natural gas decreased 25% as wellhead price decreased 29% and production increased 5% compared to the same period in the prior year.

ROYALTIES

Total royalties decreased 6% to $16.6 million for the third quarter of 2002 from $17.7 million for the same period last year. The decrease was due to lower natural gas and light oil revenue. Total royalties for the third quarter of 2002 were 16.8% of sales compared to 16.5% of sales for the same period a year ago. For the third quarter of 2002, royalties were 15.7% of sales for light oil, 15.4% for heavy oil and 21.3% for natural gas. These rates compared to 19.5%, 13.4% and 22.3%, respectively, for the same period last year.

For the nine months ended September 30, 2002, total royalties decreased 14% to $42.3 million from $49.4 million for the same period last year. Total royalties for the period were 15.7% of sales compared to 17.6% of sales for the corresponding period last year. For the first nine months of 2002, royalties were 16.1% of sales for light oil, 14.2% for heavy oil and 19.5% for natural gas. These rates compared to 19.4%, 10.9% and 26.5%, respectively, for the same period in 2001.

OPERATING EXPENSES

Operating expenses for the third quarter of 2002 decreased 21% to $18.6 million from $23.6 million for the corresponding quarter last year. This decrease is attributable to a 20% decrease in overall production as well as the disposition of higher operating cost properties. Operating expenses were $5.27 per boe for the third quarter of 2002 compared to $5.31 per boe for the third quarter of 2001. For the third quarter of 2002, operating expenses were $5.84 per barrel of light oil, $6.00 per barrel of heavy oil and $0.61 per mcf of natural gas. The operating expenses by product for the same period last year were $6.73, $5.51 and $0.70, respectively.

Operating expenses for the first nine months of 2002 decreased 11% to $55.4 million from $62.5 million for the corresponding period of 2001. This decrease is primarily due to the same factors as noted for the third quarter comparison. Operating expenses were $5.21 per boe for the first nine months of 2002 compared to $5.25 per boe a year ago. For the first nine months of 2002, operating expenses were $6.04 per barrel of light oil, $5.91 per barrel of heavy oil and $0.60 per mcf of natural gas versus $6.81, $5.62 and $0.62, respectively, for the same period a year earlier.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses for the third quarter of 2002 increased to $1.7 million from $1.4 million for the same quarter of 2001. On a unit of production basis, these expenses increased from $0.31 per boe to $0.49 per boe mainly due to lower production. In accordance with full cost accounting policy, $1.7 million of expenses were capitalized in the third quarter of 2002 compared to $1.4 million in the same quarter last year.

General and administrative expenses increased to $5.1 million for the nine months ended September 30, 2002 from $3.8 million for the same period last year. On a unit of production basis, these expenses increased from $0.32 per boe to $0.48 per boe. In accordance with full cost accounting policy, $5.1 million of expenses were capitalized in the first nine months of 2002 compared to $3.8 million in the same period a year ago.

INTEREST EXPENSES

Interest expenses on long-term notes and bank debt decreased to $6.3 million for the third quarter of 2002 from $10.0 million for the same quarter last year. For the first nine months of 2002, interest expenses decreased to $17.2 million from $23.4 million for the same period last year. Average debt levels were lower during the first nine months of 2002 as the outstanding bank debt was reduced and interest rates on the Company’s senior secured notes and senior subordinated notes were reduced from 7.23 to 5.1 percent and from 10.5 to 8.6 percent, respectively, as a result of the interest rate swaps that the Company negotiated in December 2001. The interest rate swaps were settled during the third quarter for total proceeds of $14.1 million, which is being amortized as a reduction of interest expense over the original terms of the swap agreements.

DEPLETION, DEPRECIATION AND AMORTIZATION

The provision for depletion, depreciation and amortization decreased to $26.9 million for the third quarter of 2002 compared to $40.3 million for the same quarter last year. This decrease is due to lower production and the ceiling test write-down taken at yearend 2001. On a unit of production basis, the provision for the current quarter was $7.63 per boe compared to $9.10 per boe for the same quarter in 2001.

Depletion, depreciation and amortization decreased to $80.5 million for the first nine months of 2002 compared to $97.0 million for the same period last year. On a unit of production basis, the provision for the current period was $7.56 per boe compared to $8.14 per boe for the same period a year earlier.

SITE RESTORATION COSTS

The current quarter provision for restoration costs decreased to $0.7 million from $1.0 million for the same quarter last year. On a unit of production basis, the provision for the third quarter of 2002 was $0.19 per boe compared to $0.22 per boe for the corresponding quarter of last year.

Site restoration costs for the nine months ended September 30, 2002 decreased to $2.1 million from $3.0 million for the same period last year due to lower production. On a unit of production basis, the provision for the first nine months of 2002 was $0.20 per boe compared to $0.25 per boe 2001.

FOREIGN EXCHANGE

Effective January 1, 2002, the Company adopted the Canadian Institute of Chartered Accountants (“CICA”) amended accounting standard with respect to foreign currency translation. The amended standard eliminates the practice to defer and amortize foreign exchange gains and losses on long-term monetary items. As a result, all foreign exchange gains and losses on long-term monetary items are now recognized in earnings based on the exchange rates at the end of the reporting periods. The amended standard also requires that prior years’ comparative figures be restated to comply with the new standard.

The application of the new standard resulted in an unrealized foreign exchange loss of $13.9 million in the third quarter of 2002 compared to a $12.7 million loss in the corresponding quarter of 2001. The foreign exchange gain for the nine months ended September 30, 2002 was $1.4 million compared to a loss of $13.4 million for the same period last year. The 2002 gain is based on the translation of the Company’s U.S. dollar denominated long-term debt at 0.6306 at September 30, 2002 compared to 0.6279 at December 31, 2001. The 2001 loss is based on the translation of the U.S. dollar denominated senior secured notes at 0.6333 at September 30, 2001 compared to 0.6660 at December 31, 2000 along with the senior subordinated notes translated at 0.6333 at September 30, 2001 compared to 0.6582 on February 13, 2001 when the notes were issued.

INCOME TAXES

Current tax expenses were $2.7 million for the third quarter of 2002 compared to $2.6 million for the same quarter of 2001. The current tax expense is comprised of $2.3 million of Saskatchewan Capital Tax and $0.4 million of Large Corporation Tax compared to $2.2 million of Saskatchewan Capital Tax and $0.4 million of Large Corporation Tax for the same period last year.

Current tax expenses were $7.3 million for the first nine months of 2002 compared to $6.6 million for the same period last year. The current tax expense is comprised of $6.1 million of Saskatchewan Capital Tax and $1.2 million of Large Corporation Tax, compared to $5.3 million of Saskatchewan Capital Tax and $1.3 million of Large Corporation Tax in 2001.

NET INCOME

Net income for the third quarter of 2002 was $3.7 million compared to a loss of $4.6 million in the third quarter of 2001. For the first nine months of 2002, net income was $32.3 million compared to $4.3 million for the first nine months of 2001. This increase is mainly the result of higher heavy oil prices in 2002 and a foreign exchange gain during 2002 compared to a foreign exchange loss in 2001.

LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2002, total net debt (including working capital) was $344.0 million compared to $497.2 million at September 30, 2001 and $379.1 million at December 31, 2001. The decrease in total debt at the end of the third quarter of 2002 was the result of cash flow from operations exceeding capital spending, proceeds from property dispositions and proceeds received in the third quarter on the settlement of interest rate swaps.

Effective January 1, 2002, the CICA’s Emerging Issues Committee issued an abstract giving guidance on disclosure of callable debt obligations. Specifically, the abstract requires the classification of borrowings under a 364-day revolving credit facility as current liabilities. The Company’s bank loans are structured under this type of credit facility and, as such, have been reclassified as current liabilities.

The senior secured notes are governed by certain financial covenants measured at the end of each fiscal quarter. The principal covenants are: (i) consolidated tangible net worth not to be less than $200 million, excluding accounting ceiling test write-down (such net worth was $515 million as at September 30, 2002); (ii) consolidated total debt not to exceed 300% of consolidated cash flow (such ratio was 166% as at September 30, 2002); and (iii) consolidated cash flow not to be less than 400% of consolidated interest expense (such ratio was 714% as at September 30, 2002). The senior subordinated notes are due February 2011 and do not require any financial covenant maintenance.

CAPITAL EXPENDITURES

Exploration and development expenditures decreased to $103.6 million for the first nine months of 2002 compared to $116.4 million for the same period last year. The Company’s total capital expenditures for these periods are summarized as follows:

Nine Months ended September 30 ($ thousands)	2002		2001

Land	9,955		9,078
Seismic	5,933		6,357
Drilling and completions	62,416		62,700
Equipment	19,176		32,118
Other	6,092		6,160
Total exploration and development	103,572		116,413
Corporate acquisitions	—		249,152
Property acquisitions	11,813		43,930
Property dispositions	(54,428	)	(1,402	)
Net capital expenditures	60,957		408,093

CONSOLIDATED BALANCE SHEETS

	September 30			December 31
(thousands) (unaudited)	2002			2001
				(restated — notes 2 & 3)
ASSETS
Current assets

Cash and short-term investments	$	11,437		$	—
Accounts receivable	51,891			44,300
Properties held for sale	—			46,895
	63,328			91,195

Deferred financing charges	7,887			8,674
Petroleum and natural gas properties	893,597			867,177
	$	964,812		$	967,046

LIABILITIES
Current liabilities
Accounts payable and accrued liabilities	$	79,025		$	64,334
Current portion of long-term debt (note 3)	—			75,820
	79,025			140,154
Long-term debt (note 3)	328,261			330,102
Deferred charges (note 5)	18,018			18,694
Provision for future site restoration costs	22,643			20,541
Future income taxes	170,893			146,446
	618,840			655,937

SHAREHOLDERS’ EQUITY
Share capital (note 4)	397,252			394,734

Deficit	(51,280		)	(83,625		)
	345,972			311,109
	$	964,812		$	967,046

See accompanying notes to the consolidated financial statements

CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS (DEFICIT)

	Three Months Ended September 30							Nine Months Ended September 30
(thousands, except per share data) (unaudited)	2002				2001			2002			2001
Revenue
Petroleum and natural gas sales	$		94,633		$	101,689		$	265,270		$	265,373
Royalties	(16,634			)	(17,745		)	(42,270		)	(49,372		)
	77,999				83,944			223,000			216,001
Expenses
Operating	18,610				23,557			55,424			62,544
General and administrative	1,718				1,380			5,124			3,791
Interest (note 3)	6,314				10,040			17,212			23,364
Foreign exchange (gain) loss (note 2)	13,889				12,689			(1,408		)	13,447
Depletion, depreciation and amortization	26,945				40,328			80,484			96,988
Site restoration costs	674				977			2,102			2,977
	68,150				88,971			158,938			203,111

Income (loss) before income taxes	9,849				(5,027		)	64,062			12,890
Income taxes (recovery)
Current	2,720				2,637			7,270			6,585
Future	3,442				(3,038		)	24,447			2,041
	6,162				(401		)	31,717			8,626
Net income (loss)	$	3,687			$	(4,626	)	32,345			4,264

Retained earnings (deficit), beginning of period, as previously reported								(75,954		)	52,555

Accounting policy change (note 2)								(7,671		)	927
Retained earnings (deficit), beginning of period, as restated								(83,625		)	53,482
Retained earnings (deficit), end of period								$	(51,280	)	$	57,746

Net income (loss) per share

Basic	$	0.07			$	(0.09	)	$	0.62		$	0.09

Diluted	$	0.07			$	(0.09	)	$	0.61		$	0.09

See accompanying notes to the consolidated financial statements

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months Ended September 30						Nine Months Ended September 30
(thousands, except per share data) (unaudited)	2002			2001			2002			2001
Cash provided by (used in):
OPERATING ACTIVITIES
Net income (loss)	$	3,687		$	(4,626	)	$	32,345		$	4,264
Items not affecting cash:
Site restoration costs	674			977			2,102			2,977
Foreign exchange (gain) loss	13,889			12,689			(1,408		)	13,447
Depletion, depreciation and amortization	26,945			40,328			80,484			96,988
Future income taxes (recovery)	3,442			(3,038		)	24,447			2,041

Cash flow from operations	48,637			46,330			137,970			119,717
Change in non-cash working capital	3,190			(7,871		)	(13,128		)	(573		)
Increase in deferred charge	13,306			—			13,306			—
Deferred revenue	(4,712		)	—			(13,982		)	—
	60,421			38,459			124,166			119,144

FINANCING ACTIVITIES
Issue of senior subordinated term notes	—			—			—			227,895
Increase (decrease) in bank loan	(10,282		)	8,620			(76,253		)	(35,118		)
Increase in deferred financing charges	—			(526		)	—			(8,909		)
Repurchase of common shares	(55		)	—			(55		)	—
Issue of shares (net of issue expenses)	1,851			9			2,573			1,444
	(8,486)			8,103			(73,735		)	185,312

INVESTING ACTIVITIES
Corporate acquisitions	—			(519		)	—			(249,152		)
Items not affecting cash:
Issue of shares on acquisition	—			45			—			68,104
Assumption of long-term debt	—			—			—			36,356
Assumption of working capital	—			—			—			(2,734		)
	—			(474		)	—			(147,426		)
Petroleum and natural gas property expenditures	(30,733		)	(33,894		)	(115,385		)	(160,343		)
Disposal of petroleum and natural gas properties	(128		)	500			54,428			1,402
Properties held for sale	—			—			(46,895		)	—
Change in materials and supplies	589			707			1,735			276
Change in non-cash working capital	(10,226		)	(13,401		)	67,123			1,635

	(40,498)			(46,562		)	(38,994		)	(304,456		)
Change in cash and short-term investments	11,437			—			11,437			—
Cash and short-term investments, beginning of period	—			—			—			—

Cash and short-term investments, end of period	$	11,437		$	—		$	11,437		$	—

Cash flow from operations per share
Basic	$	0.93		$	0.89		$	2.65		$	2.45
Diluted	$	0.91		$	0.87		$	2.60		$	2.40

See accompanying notes to the consolidated financial statements

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Three Months and Nine Months Ended September 30, 2002 and 2001

1. ACCOUNTING POLICIES

The interim consolidated financial statements of Baytex Energy Ltd. (the “Company”) are presented in accordance with Canadian generally accepted accounting principles. The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements of the Company as at December 31, 2001, except as described in notes 2 and 3. The interim consolidated financial statements contain disclosures, which are supplemental to the Company’s annual consolidated financial statements. Certain disclosures, which are normally required to be included in the notes to the annual consolidated financial statements, have been condensed or omitted. The interim consolidated financial statements should be read in conjunction with the Company’s consolidated financial statements and notes thereto for the year ended December 31, 2001.

2. CHANGES IN ACCOUNTING POLICY

Foreign Currency

Effective January 1, 2002, the Company retroactively adopted the Canadian Institute of Chartered Accountants (CICA) amended accounting standard with respect to accounting for foreign currency translation. As a result of the amendments, all exchange gains and losses on long-term monetary items that do not qualify for hedge accounting are recognized in income. Previously, these exchange gains and losses were deferred and amortized over the remaining life of the monetary item. The impact of the amended standard on the three month period ended September 30, 2002 was to decrease net income by $7.8 million (2001 — decrease of $7.0 million) and on the nine month period ended September 30, 2002 was to increase net income by $0.8 million (2001 — decrease of $7.3 million). The effect of this change on the December 31, 2001 Consolidated Balance Sheet is a decrease in unrealized foreign exchange loss of $13.7 million and an increase in the deficit of $7.7 million.

Stock-based Compensation

Effective January 1, 2002, the Company adopted the new recommendations of the CICA with respect to stock-based compensation. In accordance with the new standard, the Company has elected to continue its policy of accounting for employee stock options based on intrinsic values and will disclose the pro forma results of using the fair value based method. The new recommendations apply to options granted after January 1, 2002.

3. LONG-TERM DEBT

	September 30		December 31
(thousands)	2002		2001
Bank loan	$	—	$	73,820
Senior secured term notes (US$57,000,000)	90,391		90,778
Senior subordinated term notes (US$150,000,000)	237,870		238,890
Other long-term debt	—		2,434
	328,261		405,922
Less: current portion	—		75,820
	$	328,261	$	330,102

Effective January 1, 2002, the Company has classified borrowing under its bank facilities as a current liability as required by new guidance under the CICA’s Emerging Issues Committee Abstract 122. The bank loan at December 31, 2001 has been restated to conform to the current presentation.

Bank loan

At September 30, 2002, the bank facilities were limited to a total commitment under the facilities of $77 million and a borrowing

base of $165 million which is defined to include the senior secured term notes.

Interest Expense

The Company has incurred interest expense on its outstanding debt as follows:

	Three Months Ended September 30				Nine Months Ended September 30
(thousands)	2002		2001		2002		2001
Bank loan	$	125	$	2,078	$	531	$	3,259
Long-term debt	6,189		7,962		16,681		20,158
Total interest	$	6,314	$	10,040	$	17,212	$	23,364

4. SHARE CAPITAL

The Company has an unlimited number of common shares in its authorized share capital.

Issued and Outstanding:

Common shares

(thousands)	# of shares		Amount
Balance — January 1, 2002	52,008		$	394,734
Normal course issuer bid	(9	)	(55		)
Exercise of stock options	602		2,573
Balance — September 30, 2002	52,601		$	397,252

Stock options

			Weighted average
(thousands)	# of options		exercise price
Balance — January 1, 2002	4,468		$	6.19
Granted	205		6.66
Exercised	(602	)	4.27
Cancelled	(187	)	5.69
Balance — September 30, 2002	3,884		$	6.53
Exercisable — September 30, 2002	1,285		$	7.02

The Company accounts for its stock options using intrinsic values. On this basis, compensation costs are not required to be recognized in the financial statements for stock options granted at market value. Had compensation costs for the Company’s stock option plan been determined based on the fair-value method at the dates of grants under the plan after January 1, 2002, the Company’s pro-forma net income for the three months ended September 30, 2002 would have been reduced by $0.06 million (nine months ended September 30, 2002 - $0.10 million) and earnings per share for those periods would be the same as those reported. The fair value of the stock options granted is estimated on the grant date using the Black-Scholes option-pricing model using the following assumptions: risk free interest rate of 4%; expected life of 4 years; and expected volatility of 57%.

Normal course issuer bid

During the three months ended September 30, 2002, the Company acquired 9,200 of its common shares through a normal course issuer bid program at an average cost of $6.03 per share. The shares purchased under the normal course issuer bid were cancelled.

5. DEFERRED CHARGES

(thousands)	September 30, 2002		December 31, 2001
Deferred commodity contract gain	$	4,712	$	18,694
Deferred interest cost reduction (note 6)	13,306		—
	$	18,018	$	18,694

6. DERIVATIVE CONTRACTS

In August 2002, the Company terminated all outstanding interest rate swap agreements for total proceeds of $14.1 million. This amount has been deferred and is being amortized as a reduction of interest expense over the original terms of the agreements.

For the period November 1, 2002 to October 31, 2003, the Company has entered into natural gas sales contracts for 15,000 GJ per day for fixed prices averaging $5.35/GJ and 10,000 GJ per day of collar contracts at prices between $4.20/GJ and $7.22/GJ.

On October 15, 2002, the Company entered into a long-term crude oil supply contract which requires the delivery of 20,000 barrels per day of Lloydminster Blend crude oil at a price fixed at 71% of the NYMEX WTI oil price for an initial term of five years commencing January 1, 2003. During the first year of this term, the contracted volume will increase from 9,000 barrels per day in January 2003 reaching the full 20,000 barrels per day in October 2003 and thereafter.

7. SUPPLEMENTAL CASH FLOW INFORMATION

	Three Months Ended September 30					Nine Months Ended September 30
(thousands)	2002			2001		2002			2001
Interest paid	$	9,853		$	15,715	$	23,634		$	20,680
Income taxes paid (refunded)	$	(4,237	)	$	5,568	$	(3,986	)	$	12,837

8. COMPARATIVE FIGURES

Certain comparative figures have been reclassified to conform to current year’s presentation.

CORPORATE INFORMATION

BOARD OF DIRECTORS	OFFICERS	HEAD OFFICE

John A. Brussa	Dale O. Shwed	Suite 2200, Bow Valley Square II
Partner	President and Chief Executive Officer	205 — 5th Avenue S.W.
Burnet, Duckworth & Palmer LLP		Calgary, Alberta T2P 2V7
		Calgary, Alberta T2P 2V7
	Raymond T. Chan, CA
W.A. Blake Cassidy	Senior Vice-President and	Phone:	(403) 269-4282
Retired Banker	Chief Financial Officer	Fax:	(403) 205-3845
		Website:	www.baytex.ab.ca
Raymond T. Chan	Ralph W. Gibson
Senior Vice-President	Vice-President, Marketing
Baytex Energy Ltd.		AUDITORS
	Daniel B. Horner, LLB	Deloitte & Touche LLP
	Vice-President, Land	Deloitte & Touche LLP
Fred C. Coles	Vice-President, Land
Independent Businessman
	John G. Leach, CA	BANKERS
Dennis L. Nerland	Vice-President, Finance	Royal Bank of Canada
Partner	and Administration	Bank of Montreal
Shea Nerland Calnan		BNPParibas (Canada)

	S. Dale McAuley
Dale O. Shwed	Vice-President, Operations
President
Baytex Energy Ltd.		LEGAL COUNSEL
	Richard W. Naden	Burnet, Duckworth & Palmer LLP
	Vice-President, Production

	Garry J. Wasylycia
	Vice-President, Exploration	RESERVES ENGINEERS
		Outtrim Szabo Associates Ltd.

	Shannon M. Gangl
	Secretary
	Partner	TRANSFER AGENT
	Burnet, Duckworth & Palmer LLP	Valiant Trust Company

		EXCHANGE LISTING
		The Toronto Stock Exchange
		Stock Symbol BTE

ADVISORY

Certain statements in this interim report are “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995. Specifically, this interim report contains forward-looking statements relating to Management’s approach to operations, expectations relating to the number of wells, amount and timing of capital projects, foreign exchange rates, interest rates, worldwide and industry production, prices of oil and gas, heavy oil differentials, company production, cash flow and debt levels. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: general economic, market and business conditions; industry capacity; competitive action by other companies; fluctuations in oil and gas prices; the ability to produce and transport crude oil and natural gas to markets; the result of exploration and development drilling and related activities; fluctuation in foreign currency exchange rates; the imprecision of reserve estimates; the ability of suppliers to meet commitments; actions by governmental authorities including increases in taxes; decisions or approvals of administrative tribunals; change in environmental and other regulations; risks associated with oil and gas operations; the weather in the Company’s areas of operations; and other factors, many of which are beyond the control of the Company. There is no representation by Baytex that actual results achieved during the forecast period will be the same in whole or in part as those forecast.